If you assume 5.0 watts (peak) per square foot for thin film photovoltaic, you end up requiring 4.6 acres per peak megawatt-hour (MWp), about the same as Nevada Solar One’s solar thermal farm (4.7 acres per MWp). Thin film PV panels now have a factory cost of about $1.00 per watt, which is quite cost competitive with solar thermal. Remember there isn’t nearly as much balance of plant with photovoltaic. With solar thermal, the solar field is just the beginning – you need the heat concentrators, the boiler, the turbine, and the condensing loop.

While Ausra and others have designs somewhat more space efficient than Nevada Solar One (Ausra’s proposed Carrizo plant will only require about 3.6 acres per MWp), more efficient PVs require far less space. A high-end PV will generate 20 watts per square foot (peak), which equates to 1.15 acres per MWp. Needless to say the costs per watt for these higher efficiency PV panels are 2-3x the costs for the thin film panels – at least at present, polysilicon may decline in price, and who can say how the electrical input required to bake monocrystaline PV is costed? Also, we don’t have good history yet on the longevity of thin film PV.

Which of these systems delivers lower lifetime costs per kWh?

The costs for photovoltaic solutions are better documented, although utility scale photovoltaic installations are just beginning to be implemented. The most significant variable isn’t peak output, which is somewhat easier to calculate, but kilowatt-hour output per year. Variables affecting this yield, of course, are the latitude and the weather conditions at each site. Notwithstanding the fact that some latitudes are cloudier than others, in the higher latitudes, say beyond 50 degrees north, you can multiply your peak hourly output by about 1,200 to get your yearly output. If you have an array that delivers 1.0 kilowatts in full sun, then that array will deliver about 1,200 kWh per year. In the temperate latitudes, around 35 degrees north, that multiple increases to around 1,600, and in the tropics, it can get over 2,000x.

Another way to stretch the output of photovoltaic systems is to point them at the sun, the same way solar thermal mirrors track the sun. This can increase yields per collector area by 50-100%, more if optical concentrators are used, but this also increases costs.

Calculating costs per kilowatt-hour are also impacted by how long the system will last, and how much output will degrade each year. Solar thermal systems are more expensive to maintain, but can last 50 years or more. Monocrystaline photovoltaic systems only degrade about 0.5% per year, which means they still produce at around 80% of their original efficiency at age 25. But by age 50 their output will be significantly degraded. Nobody knows yet how long thin film arrays will last.

At this point it isn’t clear which systems are cheaper. Taking the total installation price divided by peak megawatt output to get a installation cost per 1.0 megawatt output (peak), is a cost that is easier to objectively calculate, To cite a recently commissioned solar thermal plant, Acciona’s Nevada Solar One plant cost a reported $260 million and will output 64 megawatts at peak, or about $4.1 million per megawatt. For an example of a utility scale thin film plant, Optisolar’s 40 megawatt Sarnia facility is reported to cost $300 million, or $7.5M per megawatt.

Getting to cost per kWh from peak output is not easy. Annual kWh yield is influenced by latitude, weather, and whether or not the array is tracking. Lifetime maintenance costs are a factor, and the life of the system and whether or not there is annual degradation are factors. At the end of the day, the solar thermal industry is claiming they can immediately deliver power for about $.12 per kWh, and they think they will eventually get that cost down to around $.07 per kWh. The thin film folks haven’t disclosed their costs – but with the incentives of feed-in tariffs this technology will continue to be developed.

I believe we should invest heavily in both solar thermal and PV. Something that is left out here that I think is relevant is that solar thermal plants, right now, have a cost effective way of producing electricity after sundown during peak evening hours using storage tanks. Cost effective ways to store an electric charge on a utility scale are who knows how far away. PV annual production capacity seems like it will much higher than solar thermal plants, especially with roll to roll printing of thin film. I haven’t investigated this, but those are the claims from the thin film industry. The vast square miles that need to be installed in the coming decade mean we need to chose both so that we can move away from fossil fuels as quickly and broadly as possible.

It may turn out that PV belongs on factory and household roofs, where it suffers no transmission losses, while the tracking mirrors occupy the deserts where they can be more easily maintained and constructed en masse.

The big difference is that PV stops generating as soon as the sun goes down or clouds come out. Heat storage for solar thermal can provide stable generation and, in some newer systems, up to 16 hours of overnight generation. When you talk about electrical grid stability, that is huge. Otherwise, you need to back up your PV with nuclear or coal plants for base power generation.

til: Electricial grid stability is a huge factor, and the intermittant energy harvesting associated with solar and wind technologies necessitates massive storage solutions. One commenter here has claimed Ausra (a new solar thermal company) intends to store thermal mass – probably steam – within underground caverns. That would be a practical solution since a cubic meter of steam stored at 1,500 PSI will only yield about 50 kWh of electricity. This means a gigawatt-hour electricity would require require 20,000 cubic meters stored steam – which might be prohibitive using tanks. The cube root of 20,000 is only 27.14, and a cube-shaped cavern 27 meters on each side is not inconceivable at all.

Don’t write off other storage possibilities, however. Molten salt may also be a practical solution to thermal storage. Reverse pumping of water during solar peaks to reuse the same water in a hydroelectric turbine during demand peaks is already being done, and the efficiency loss can be as low as 20%. There also rumors of large-scale batteries using new chemistries – think 50 megawatt-hour! – as well as pressurized air recovered through an electric turbine. Finally, there are many decentralized home solutions that are getting more feasible every day – surplus electricity produced during the solar peak may literally go onto the grid and pour into 10 kWh batteries in millions of garages, to be re-discharged into EVs each night.

It’s very true that we should not pick winners, and denigrate the rest. We need all solutions on the table. Thin film will have a large niche. Possibly also some part to play in the utility sector. Solar thermal will also be required, as the storage capability is in some respects designed in.
Underground steam storage caverns can be constructed easily in many geologies with explosives. Some people have even suggested underground nuclear explosions to create these vast caverns. Because the steam is part of a closed-loop system, this wouldn’t pose very much contamination risk. It would be great if nuclear bombs could actually prove useful for something.

A clarification. If PV is on an inclined roof it uses zero land, but if it is in a desert in a large plant, the panels must be spaced apart to avoid mutual shading. The land area is typically 3-5 times panel area in such installations, and the Ausra plant will normally be smaller. One should also not confuse module efficiency with overall plant efficiency; a “20%” module will often be 16% – 18% after inverter and temperature-related losses.

IF the solar plant had to be built in New York City or Tokyo, with its dollars per square inch prices, or IF photovoltaic could produce electricity with any of the highly valued characterisitcs of solar thermal, such as smooth output and time displaced output control and complete predictability of output at a time hours in the future, THEN considerations of space might actually be a relevant issue. But there not, and so discussing the space requirements when talking about desert areas becomes a hilariously silly enterprise, worthy as a fertile subject for the Monty Python treatment. Sounds for all the world as though a PV supporter looked everywhere to find SOMETHING that this obsolete technology has going for it, and came up with this
nonsensical characterisistic. The last, very last, thing any utility buyer cares about is how much barren land it took to produce the power being offered for sale. I can’t believe the editors allowed this preposterously dumb article to get on the blog. Must have been a VERY slow news day.

With thin film solar panels, you need to include batteries if you want the power to extend into non-daylight hours, just as solar thermal requires molten salt tanks. I suspect batteries are far more expensive than molten salt.

Molten salts. Well you also need a LOT of molten salt to store a GWh. Much less than pressurized water, due to higher volumetric heat capacity of molten salts, and higher temperature storage which decreases storage volume directly as well as indirectly (ie through higher cycle efficiencies possible with higher temperatures).

But, the storage volume is still very large. Molten salts could also be stored underground.